The present invention relates generally to subterranean treatment operations, and more particularly to using wavelet analysis in subterranean treatment operations.
Subterranean formations penetrated by well bores are often treated to increase the production therefrom. Common treatment methods include water-flooding, carbon dioxide (CO2) flooding, conformance applications, and fracture stimulation, among others. When a fluid is injected into a subterranean formation, certain changes occurring downhole during such injection process (such as the creation or extension of a fracture therein or the contacting of a subterranean boundary by the injected fluid, for example) send different pressure frequency spectra and wave intensities to the surface. Pressure waves generated and reflected during fluid injection are conventionally captured and evaluated so as to monitor changes in the downhole environment during the time period in which the fluid is injected.
Monitoring and analysis techniques used in conventional water-flooding and/or CO2-flooding operations often encounter difficulty in recognizing certain subterranean conditions such as boundaries or heterogeneities (e.g., regions of high permeability into which the injected fluid may flow readily, thereby creating undesirable “fingering”) within the subterranean formation. This difficulty is problematic, because it prevents operators from prompt execution of a remediative step, such as adjusting the viscosity of the injected fluid.
Monitoring and analysis techniques conventionally used in conformance applications are also problematic. As referred to herein, the term “conformance applications” will be understood to mean applications comprising the injection of a first fluid into a portion of a subterranean formation so as to alter the flow profile of a second fluid injected into, or produced from, a subterranean formation. For example, a conformance application may involve the injection of a sealant into a subterranean formation so as to minimize entry into a well bore of an unwanted fluid. Monitoring and analysis techniques used in conventional conformance applications often encounter difficulty in recognizing certain subterranean conditions. An example of such a condition is the presence of boundaries within the formation. This difficulty is problematic, because it prevents operators from prompt execution of a remediative step, such as adjusting the pressure of the injected fluid, for example.
Fracture stimulation is another application where conventional monitoring and analysis techniques are problematic. Fracture stimulation comprises the intentional fracturing of the subterranean formation by pumping a fracturing fluid into a well bore and against a selected surface of a subterranean formation intersected by the well bore. The fracturing fluid is pumped at a pressure sufficient that the earthen material in the subterranean formation breaks or separates to initiate a fracture in the formation.
A fracture typically has a narrow opening that extends laterally from the well. To prevent such opening from closing completely when the fracturing pressure is relieved, the fracturing fluid typically carries a granular or particulate material, referred to as “proppant,” into the opening of the fracture. This material remains in the fracture after the fracturing process is finished. Ideally, the proppant in the fracture holds apart the separated earthen walls of the formation to keep the fracture open and to provide flow paths through which hydrocarbons from the formation can flow into the well bore at increased rates relative to the flow rates through the unfractured formation. Fracturing processes are intended to enhance hydrocarbon production from the fractured formation. In some circumstances, however, the fracturing process may terminate prematurely, for a variety of reasons. For example, the “pad” portion of the fracturing fluid, which is intended to advance ahead of the proppant as the fracture progresses, may undesirably “leak off” into smaller fractures in the formation, which may cause the proppant to reach the fracture tip and create an undesirable “screenout” condition. Thus, properly analyzing fracture behavior is a very important aspect of the fracturing process.
In connection with analyzing fracture behavior, various physical parameters of the subterranean formation are commonly monitored. Physical parameters such as pressure and temperature are commonly converted into electronic signals with downhole transducers. Conventional fracturing operations typically begin with a determination of the “closure pressure” of the subterranean formation, which determination is often accomplished by performing reduced-scale fracturing, e.g., a “mini-frac” or a “micro-frac,” before commencing full-scale fracturing of the formation. For example, in one embodiment of a micro-frac test, a small volume of clear fluid containing no proppant may be pumped into a well bore at a low flowrate (typically less than 10 gallons per minute). This may generate a fracture extending up to about 15 feet into the subterranean formation, and generate acoustic noise in the form of a pressure wave or signal received by a sensing device within the well bore. In one embodiment of a mini-frac test, the formation is fractured using a formulation of the fracturing fluid that will be used in the full-scale fracturing operation. The scale of the mini-frac may be generally about 10–15% of the full-scale fracturing operation, but the fluid used in the mini-frac will generally not contain a significant amount of proppant. Among other benefits, the mini-frac test enables an operator to determine the formation's closure pressure, along with the formation's leakoff coefficient, both of which parameters are useful in designing and analyzing the full-scale fracturing treatment. To determine the closure pressure, an operator may often plot the pressure signal versus the square root of time, and determine the closure pressure by constructing two tangent lines on the plot, and extending them so that they intersect. Typically, one tangent line will be constructed at a point on the graph representing a time immediately after the cessation of injection of the fracturing fluid; the other tangent line will typically be constructed at a point on the graph immediately after a “knee” in the pressure signal. Conventionally, the first tangent line is thought to represent a region of fluid leak-off into the face of an open subterranean fracture, while the second tangent line is thought to represent a region of slower fluid leak-off through a closed subterranean fracture. The two tangent lines are arbitrarily constructed based upon a particular operator's interpretation of a suitable tangent line. Once the two tangent lines have been drawn, their intersection is conventionally identified as the closure pressure of the formation. The method is highly subjective.
Conventionally, full-scale fracturing operations begin once the closure pressure has been determined, and are conventionally analyzed through the use of a log-log plot of a “net-pressure” signal. Upon the initiation of fracturing of the well bore, a pressure signal is received. An operator will typically subtract the pre-determined closure pressure from the pressure signal, to calculate a “net pressure.” This net pressure is then plotted versus time on a log-log plot. Conventionally, the slope of the net pressure curve is analyzed with consideration given to certain guidelines. For example, where the slope of the net pressure curve is between about 0.2 and about 0.3, the fracture is thought to be continuing to propagate. However, where the net pressure curve has a slope of about 1.0, the fracture propagation is thought to have stopped, and adverse fracture behaviors such as the onset of sand-out are thought to begin.
Conventional fracturing analysis using the log-log plot of a net pressure curve is problematic. Because of the nature of the log-log plot, a lengthy amount of time is often required before the unit slope straight line becomes well-developed and apparent. Accordingly, an operator may encounter difficulty in interpreting the net pressure curve so as to distinguish, normal, continued fracture propagation from the cessation of propagation. This difficulty may cause operators to continue to inject proppant-laden fracturing fluid into the well bore, despite the fact that the fracture is no longer capable of accepting the proppant; in such scenarios, proppant accumulates within the well bore and must be laboriously removed once the fracturing operation stops. This difficulty in distinguishing between normal fracturing and the cessation of propagation often prevents operators from timely performance of a remediative step. Such a remediative step could comprise injecting a clear fluid into the well bore so as to sweep any last amounts of proppant out of the well bore and into the formation, for example.
An operator using conventional fracture monitoring techniques such as the log-log plot of a net pressure curve may also encounter difficulty in distinguishing a pressure increase caused by actual closure of the fracture from a temporary pressure increase caused by the occurrence in the well bore of an event unrelated to the behavior of the fracture. Such temporary event is often referred to as a “tool event.” The occurrence of a temporary tool event appears quite similar on a log-log plot to the occurrence of a formation event such as closure of the fracture. This may lead to the operator misinterpreting the tool event as fracture closure, and thus halting the fracturing operation prematurely. To avoid premature stoppage of the fracture operation, the operator typically must wait, and refrain from taking any action, until a sufficient number of subsequent data points departing from the unit slope have been plotted on the net pressure curve before discounting the tool event as a spurious event not indicative of fracture closure with sufficient confidence; in some scenarios, this may require waiting several tens of minutes. Alternatively, an operator using conventional fracturing analysis techniques and encountering actual fracture closure may misinterpret it as a temporary tool event, and continue to inject proppant into the well bore, while waiting for subsequent data points to depart from the unit slope on the net pressure curve. Such misinterpretation of actual fracture closure as a temporary tool event may result in the well bore becoming loaded with proppant that never reaches the fracture, and that must be laboriously and expensively removed before the well bore may be returned to production.